The recovery of subterranean hydrocarbons, such as oil and gas, usually requires drilling boreholes thousands of feet deep. In addition to an oil rig on the surface, drilling oil and gas wells is carried out by means of a string of drill pipes connected together so as to form a drill string. Connected to the lower end of the drill string is a drill bit. The bit is typically rotated and is done so by either rotating the drill string, or by use of a downhole motor near the drill bit, or both. Drilling fluid, called “mud,” is pumped down through the drill string at high pressures and volumes (such as 3000 psi at flow rates of up to 1400 gallons per minute) to emerge through nozzles or jets in the drill bit. The mud then travels back up the hole via the annulus formed between the exterior of the drill string and the wall of the borehole. On the surface, the drilling mud is cleaned and then recirculated. The drilling mud is used to cool and lubricate the drill bit, to carry cuttings from the base of the bore to the surface, and to balance the hydrostatic pressure in the rock formations.
Modern well drilling techniques, particularly those concerned with the drilling of oil and gas wells, involve the use of several different measurement and telemetry systems to provide data regarding the formation and data regarding drilling mechanics during the drilling process. Techniques for measuring conditions downhole and the movement and location of the drilling assembly, contemporaneously with the drilling of the well, have come to be known as “measurement-while-drilling” techniques, or “MWD.” With MWD tools, data is acquired by sensors located in the drill string near the bit. This data is stored in downhole memory or may be transmitted to the surface using a telemetry system such as a mud flow telemetry device. Mud flow telemetry devices use a modulator to transmit information to an uphole or surface detector in the form of acoustic pressure waves which are modulated through the mud that is normally circulated under pressure through the drill string during drilling operations. A typical modulator is provided with a fixed stator and a motor driven rotatable rotor, each of which is formed with a plurality of spaced apart lobes. Gaps between adjacent lobes provide a plurality of openings or ports for the mud flow stream. When the ports of the stator and rotor are in direct alignment, they provide the greatest passageway for the flow of drilling mud through the modulator. When the rotor rotates relative to the stator, the alignment between the respective ports is shifted, thus interrupting the flow of mud and generating pressure pulses in the nature of acoustic signals. A motor is typically used to control the rotor to rotate at a constant velocity, thus producing a base signal with base frequency. However, by selectively slightly varying the rotation of the rotor, the base signal is modulated with encoded pressure pulses.
Both the downhole sensors and the modulator of the MWD tool require electric power. Since it is typically not feasible to run an electric power supply cable from the surface through the drill string to the sensors or the modulator, electric power must be obtained downhole. Power may be obtained downhole either from a battery pack or a turbine-generator. While the sensor electronics in a typical MWD tool may only require 3 watts of power, the modulator may require at least 60 watts and may require up to 700 watts of power. With these power requirements, power is typically provided using mud driven turbine-generators in the drill string downstream of the modulator with the sensor electronics located between the turbine and the modulator.
As mentioned above, the modulator is provided with a rotor mounted on a shaft and a fixed stator defining channels through which the mud flows. Rotation of the rotor relative to the stator acts like a valve to cause pressure modulation of the mud flow. The turbine-generator is provided with turbine blades (an impeller) which are coupled to a shaft which drives an alternator. Jamming problems are often encountered with turbine powered systems. In particular, if the modulator jams in a partially or fully closed position because of the passage of solid materials in the mud flow, the downstream turbine will temporarily slow down and reduce the power available to the modulator. Under reduced power, it is difficult or impossible to rotate the rotor of the modulator. Thus, while turbines generally provide ample power, they can fail to provide ample power due to jamming of the modulator. While batteries are not subject to power reduction due to jamming of the modulator, they produce less power than turbine-generators and eventually fail. In either case, therefore, conservation of downhole power is a prime concern.
One attempt to conserve power has been to integrate the modulator with the a turbine-generator by directly coupling a turbine impeller to a modulator rotor downstream from the impeller using a common drive shaft. The modulator rotor is further coupled by the drive shaft and a gear train located downstream of the modulator rotor to an alternator. The turbine impeller thus directly drives the modulator rotor as well as the alternator. This way the motor is not required to constantly “drive” the shaft and rotor, thus demanding much lower power. The motor only needs to speed up or slow down momentarily to encode data. However, problems arise due to fluctuations in mud flow rate and density altering the rotational speed of the turbine and thus the modulator rotor. Because the rotational velocity of the rotor controls the frequency of the base signal, if the rotor rotational speed is dynamic, the base signal frequency will also be dynamic, making demodulation of the signal difficult, if not practically impossible. As a solution, the speed of rotation of the modulator rotor is adjusted using a feedback control circuit and an electromagnetic braking circuit to stabilize the rotor speed and modulate the rotor to obtain the desired pressure wave frequency in the mud. However, during braking, power is not being generated by the alternator and thus the alternator is not able to supply power to the downhole tool components. The system thus requires that the alternator charge a capacitor during periods of non-braking so that during periods of braking, the charged capacitor can be used to provide power to the tool components instead of the alternator.
In addition to considerations of power requirements, modulator design must also be concerned with the telemetry scheme which will be used to transmit downhole data to the surface. The mud flow may be modulated in several different ways, e.g. digital pulsing, amplitude shift keying (ASK), frequency shift keying (FSK), or phase shift keying (PSK). Although energy efficient, amplitude shift keying is very sensitive to noise, and the mud pumps at the surface, as well as pipe movement, generate a substantial amount of noise. When the modulated mud flow is detected at the surface for reception of data transmitted from downhole, the noise of the mud pumps presents a significant obstacle to accurate demodulation of the telemetry signal. Digital pulsing which, while less sensitive to noise, provides a slow data transmission rate. Digital pulsing of the mud flow can achieve a data transmission rate of only about one or two bits per second. In FSK modulation, a number of cycles at a first frequency represents a “0” digital value, and a number of cycles at a second frequency represents a “1” digital value. PSK modulation uses the same carrier frequency for both a “0” value and “1” value, with different phase angles corresponding to the different digital values. A typical and conventionally used phase difference between “0” and “1” states in PSK modulation is 180°.